{"operation":"document","citation":"PHMSA Guidance, Gas Transmission Integrity Management Progress Report","title":"Gas Transmission Integrity Management Progress Report","source_type":"guidance","agency":"Pipeline and Hazardous Materials Safety Administration","status":"guidance","official":true,"published_on":null,"effective_on":null,"summary":"Gas Transmission Integrity Management Progress Report Document gasimfeb2011statusreport2011-06-01.pdf (959.61 KB) It has been seven years since the IM rule was published on December 15, 2003, and the baseline assessments of pipe that could potentially affect HCAs have mostly been completed. Thus, PHMSA is taking this opportunity to evaluate the progress and effectiveness of this major initiative. This report provides","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-progress-report-eaa4e072.json","markdown":"https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-progress-report-eaa4e072.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-progress-report-eaa4e072","source_url":"https://www.phmsa.dot.gov/pipeline/gas-transmission-integrity-management/gas-transmission-integrity-management-progress-report","body":"Gas Transmission Integrity Management Progress Report\n\nDocument\n\n gasimfeb2011statusreport2011-06-01.pdf (959.61 KB)\n\n        It has been seven years since the IM rule was published on December 15, 2003, and the baseline assessments of pipe that could potentially affect HCAs have mostly been completed. Thus, PHMSA is taking this opportunity to evaluate the progress and effectiveness of this major initiative. This report provides a discussion of PHMSA's progress in achieving the above program objectives as well as an examination of incident trends over this period.\n\n          Effective Date: Monday, August 20, 2018\n\n<<<PAGE 1>>>\n\nGas Transmission Integrity Management\nProgress Report\nFebruary 2011\n\n<<<PAGE 2>>>\n\nGas Transmission Integrity Management Progress Report\nTable of Contents\nExecutive Summary.......................................................................................................... 1\nRecent Accident History ........................................................................................................ 1\nFig. 1 - Gas Transmission Pipeline Significant Accidents 2005 – 2010 .................................. 2\nAccelerate and Improve Integrity Assessments .................................................................... 2\nPromote Rigorous Operator IM Programs ............................................................................ 3\nStrengthen Government Oversight ....................................................................................... 3\nIncrease Public Assurance in Pipeline Safety ........................................................................ 3\nGas Transmission Integrity Management Progress Report ................................................ 5\n1. Recent Accident History ................................................................................................. 5\nFig. 1: Gas Transmission Significant Incidents 2005-2010 ..................................................... 5\nTable 1: Incident History 2005-2010 ..................................................................................... 6\nFig. 2: Significant Onshore Gas Transmission Incidents; Line Pipe, \"Detectable\" Causes .... 7\n2. Accelerate and Improve Integrity Assessments ............................................................ 8\nFig. 3 – Miles of Gas Transmission Pipeline Inspected Under the IM Rule 2004-2009 ......... 9\n3. Promote Rigorous Operator IM Programs ................................................................... 10\nFig. 4 - Number of Issues Identified per Inspection for each Program Element ................. 10\nFig. 5 – Severity of Inspection Findings by Program Element ............................................. 11\nTable 2 - Most Frequently Observed Issues – 1st Round of Operator Gas IM Inspections 12\n4. Strengthen Government Oversight ............................................................................. 14\nTable 3 – Integrity Management Enforcement Results....................................................... 14\nFig. 6 – Percentage of Inspections which Resulted in Each Type of Enforcement Action .. 14\n5. Increase Public Assurance in Pipeline Safety ............................................................... 15\nFig. 7: Types of Pipeline Repairs 2004-2009 ....................................................................... 16\n6. Summary ...................................................................................................................... 18\nPage ii February 2011\n\n<<<PAGE 3>>>\n\nGas Transmission Integrity Management Progress Report\nEXECUTIVE SUMMARY\nIn 2003, the Office of Pipeline Safety (OPS) published new regulations requiring integrity management (IM)\nprograms for gas transmission pipeline operators. This landmark set of regulations is broad-reaching and\nfundamentally different from the approaches used in the past for improving pipeline safety. These regulations\nsupplement PHMSA’s prescriptive safety requirements with new requirements which are very performance and\nprocess-oriented, setting expectations for operators, yet giving them the flexibility in how they choose to comply\nwith several programmatic requirements. The primary objectives for the Gas Transmission IM Program are to:\n Accelerate and improve the quality of integrity assessments conducted on pipelines in areas with the\nhighest potential for adverse consequences (High Consequence Areas – HCAs),\n Promote a more rigorous, integrated, and systematic management of pipeline integrity and risk by\noperators,\n Strengthen government’s role in the oversight of pipeline operator integrity plans and programs, and\n Increase the public’s confidence in the safe operation of the nation’s pipeline network.\nIt has been seven years since the IM rule was published on December 15, 2003, and the baseline assessments of\npipe that could potentially affect HCAs have mostly been completed. Thus, PHMSA is taking this opportunity to\nevaluate the progress and effectiveness of this major initiative. This report provides a discussion of PHMSA’s\nprogress in achieving the above program objectives as well as an examination of incident trends over this period.\nRecent Accident History\nThe ultimate objective of the Gas Transmission pipeline IM regulations is to reduce pipeline risk through reducing\nthe likelihood and consequences from releases that affect HCAs. PHMSA expects that actual improvements in\naccident frequency and consequences due to operator activities in response to the IM requirements will be\nobservable over the long term. While some impacts may be observable in the short term (e.g., from operators\nmaking repairs to the most severe anomalies), other impacts from the IM programmatic requirements may not be\napparent for several years. Operators also have an increased awareness of less severe conditions on their pipelines\nwhich are being monitored or scheduled for repair, providing an additional level of safety not in place before the IM\nrule.\nSome measures developed using recent gas transmission pipeline incident history appears to indicate that the IM\nrule is having a positive impact on incident frequency and consequences.\nThe yearly number of reportable incidents1 from all causes has fluctuated somewhat since 2005, but there is an\noverall decreasing trend over this period (see Figure 1). A similar decreasing trend is observed when considering\nonly the subset of incident causes that are detectable by the rule’s line pipe integrity assessment requirements (e.g.,\ncorrosion, dents, and material defects).\n2\n1 Reportable Incidents for gas transmission operators are those incidents that satisfy any of the following conditions: 1) A death, or personal\ninjury necessitating in-patient hospitalization; 2) Estimated property damage of $50,000 or more, including loss to the operator and others, or\nboth, but excluding cost of gas lost; 3) Unintentional estimated gas loss of three million cubic feet or more; 4) An event that is significant in the\njudgment of the operator, even though it did not meet any of the above criteria.\n2 The results shown here are not normalized by the number of pipeline miles that gas transmission pipeline operators have reported in annual\nreports. Gas transmission operators have only been reporting IM metrics since 2004. Over 2004-2009, pipeline miles reported in annual\nreports have increased slightly, but the increase is not considered to have a significant effect on the trends shown here.\nPage 1 of 18 February 2011\n\n<<<PAGE 4>>>\n\nGas Transmission Integrity Management Progress Report\nAdditional examinations of pipeline incident frequency and consequence are provided later in this Progress Report.\n70\n60\nNumber of Significant Onshore Incidents\nAll Causes\n50\nCauses detected by IM Assessment\n40\nCorrosion Only\n30\nLinear (All Causes)\n20\nLinear (Causes detected by IM\nAssessment)\nLinear (Corrosion Only)\n10\n0\n2005 2006 2007 2008 2009 2010\nFigure 1 - Gas Transmission Pipeline Significant Accidents 2005 – 2010\nAccelerate and Improve Integrity Assessments\nThe IM rule requires that operators conduct an initial baseline assessment of their HCA-affecting pipeline segments\nby December 2012 and then perform reassessments on a period not to exceed seven years thereafter. PHMSA\ninspections and the mandated annual reporting by operators (certified by company executives) have shown that\noperators are making adequate progress toward meeting these deadlines.\nIn addition, the threat identification and risk analysis work leading up to operators’ creation of their Baseline\nAssessment Plans has yielded benefits, as has PHMSA’s efforts – working with numerous Federal and State agencies\n– to catalogue and locate those areas across the nation most susceptible to damage from pipeline failures (HCAs).\nNot only is there a vast increase in the awareness of these susceptibilities by operators (as well as responders), there\nis now for the first time a consistent understanding among operators, oversight agencies, and first responders of\nprecisely where they are located and where additional protection is warranted. Operators now have a much better\nunderstanding of which particular portions of their pipelines, as well as other facilities, have the potential to impact\nthese sensitive areas.\nNot only are these most sensitive sections of pipelines now more secure, but the assessments required by the IM\nrule are providing additional protection beyond HCAs. While operators are only required to assess the pipeline\nsegments that can affect HCAs (~6.5% of the pipeline mileage, nationwide), they have in fact smart pigged, pressure\ntested, or otherwise assessed more than 40% of the total gas transmission pipeline mileage, thus increasing safety in\nlocations well beyond the originally designated HCAs. (Identified anomalies outside HCAs must be repaired in\naccordance with §192.485.)\nThese assessments have revealed a large number of potentially injurious conditions which pipeline operators have\nremediated in accordance with the IM rule (HCA). To date, more than 1,052 serious pipeline anomalies or defects\nhave been repaired immediately after they were discovered. In addition, some 2,239 other, less serious anomalies\nPage 2 of 18 February 2011\n\n<<<PAGE 5>>>\n\nGas Transmission Integrity Management Progress Report\nhave been repaired on a scheduled timeframe allowed in the rule – all of these occurring in sections of pipeline\nsystems which could adversely impact the nation’s HCAs.\nPromote Rigorous Operator IM Programs\nThe IM rule goes beyond simply assessing pipeline segments and repairing defects. Improving operators’\nmanagement of pipeline integrity, their associated analytical processes, and their across-the-board application of\nrigorous risk management is also a critical objective of PHMSA’s IM rule. The ability to integrate and analyze threat\nand integrity related data from many sources is critical to proactive safety management. In creating a robust IM\nprogram, PHMSA’s regulations identify sixteen essential program elements, which must be fully developed by\noperators in order to comply with the rule.\nPHMSA inspections have shown that operators have made substantial progress in developing these program\nelements. However, there are areas that still require significant industry attention. These include the program\nelements that go beyond assessing and repairing line pipe to prevent and mitigate accidents (e.g., Threat\nIdentification and Risk Analysis, and the Preventive and Mitigative Measures Program Element). PHMSA recognizes\nthat each pipeline is unique with a pipeline-specific risk profile dependent on the pipeline location, operating\nenvironment, and numerous other factors. For this reason, PHMSA’s IM rule requires operators to develop the\nprocesses and tools needed to identify and analyze these unique risks – risks which can vary considerably both from\none pipeline to another, as well as from end-to-end of any given pipeline. The IM rule also requires operators to\nhave systematic approaches to use this risk information to identify and implement additional preventive and\nmitigative measures to prevent releases and further reduce risk beyond the level achieved through repairing defects\nidentified through integrity assessment. While operators have understandably devoted significant resources to\ncompleting their baseline assessments to meet the initial deadlines in the regulations, they still need to devote more\neffort and resources to those elements considered to be crucial for a mature IM Program - specifically risk analysis,\nthe identification and implementation of additional preventive and mitigative measures, and the ongoing and\ncontinuing improvement of IM program processes.\nStrengthen Government Oversight\nAccompanying the new IM rule, PHMSA launched a new inspection program in 2005 to assure compliance with the\nnew IM requirements and promote improved operator IM Programs. A comprehensive set of inspection protocols\nwere developed that not only checked for compliance with the rule’s prescriptive requirements, but also supported\na detailed audit of an operator’s management and analytical systems, processes, and practices to manage pipeline\nintegrity. The insights from these inspections are summarized later in this report.\nWhen operators fall short of meeting the rule’s requirements for IM Program development, PHMSA takes\nenforcement action to accelerate program development and address program deficiencies. Through the first two\nrounds of IM inspections, PHMSA has issued enforcement letters for 76% of inspections. When violations of the\nrule’s prescriptive requirements occur, PHMSA has not hesitated to exercise its civil penalty authority. For the initial\nset of operator IM inspections, the average civil penalty was approximately $125,000.\nIncrease Public Assurance in Pipeline Safety\nTransparency to the public and the regulated community has been a hallmark of the IM Program since its inception.\nAfter the rule was issued, PHMSA developed the Implementing Integrity Management web site to provide\ninformation on the rule and PHMSA’s oversight efforts. This publicly accessible web site includes more than 200\nFrequently Asked Questions to explain the rule provisions and PHMSA’s expectations. This resource also provides\naccess to inspection protocols, an IM fact sheet, a glossary of IM terminology, a flow chart of the IM process,\nreference documents, and industry performance measures. With the 2007 launch of PHMSA’s enforcement\ntransparency web site, the public now has access to information on enforcement cases stemming from PHMSA’s IM\ninspections as well. The recent addition of operator-specific reports to the Stakeholder Communications web site\nnow makes it even easier for information on IM inspections and enforcement to be accessed for a given operator.\nPage 3 of 18 February 2011\n\n<<<PAGE 6>>>\n\nGas Transmission Integrity Management Progress Report\nDuring the development of these web sites, as well as in several public meetings, PHMSA has engaged its public\nstakeholders as well as the operator community for input on how to improve communication and understanding of\nthe IM Program.\nPage 4 of 18 February 2011\n\n<<<PAGE 7>>>\n\nGas Transmission Integrity Management Progress Report\nGAS TRANSMISSION INTEGRITY MANAGEMENT PROGRESS REPORT\n1. Recent Accident History\nThe ultimate objective of the gas transmission pipeline integrity management regulations is to reduce pipeline risk\nthrough reducing the likelihood and consequences of pipeline failures. It is expected that actual improvements in\nincident frequency and consequences due to operator activities in response to the IM requirements will be\nobservable over the long term. Here we look at gas transmission pipeline reportable incident data over different\nperiods related to the IM rule requirements to determine if any short term trends can be observed.\nThe periods that are considered are related to the following dates:\nDecember 17, 2004 – Gas transmission pipeline operators were required to have a written integrity\nmanagement program developed by this date.\nDecember 17, 2007 – Gas transmission pipeline operators were required to complete baseline integrity\nassessments of 50% of their HCA mileage by this date.\nDecember 17, 2012 – Operators are required to complete baseline assessments of all of their HCA mileage\nby this date.\n70\n60\nNumber of Significant Onshore Incidents\nAll Causes\n50\nCauses detected by IM Assessment\n40\nCorrosion Only\n30\nLinear (All Causes)\n20\nLinear (Causes detected by IM\nAssessment)\nLinear (Corrosion Only)\n10\n0\n2005 2006 2007 2008 2009 2010\nFigure 1: Gas Transmission Significant Incidents 2005-2010\nFigure 1 shows that over the years since gas transmission operators were required to develop an integrity\nmanagement program, there has been a slight downward trend in the annual number of significant incidents3\n.\n3 The results shown here are not normalized by the number of pipeline miles that gas transmission pipeline\noperators have reported in annual reports. Over 2005-2009, total onshore gas transmission pipeline miles reported\nPage 5 of 18 February 2011\n\n<<<PAGE 8>>>\n\nGas Transmission Integrity Management Progress Report\nIntegrity Management regulations include some requirements that address pipeline risks from all causes. However,\nrequirements for integrity assessment and repair primarily address risks from a subset of possible incident causes\nthat may be detected during integrity assessments, such as corrosion and certain materials defects. The\nrequirements for integrity assessments do not affect most incidents caused by mechanical damage (i.e., excavation\ndamage, natural forces damage, other outside force damage), incorrect operation, or equipment failures. If we wish\nto focus on the possible effects of the IM requirements for integrity assessment, then incidents caused by the subset\nof causes that are detectable during integrity assessments should be considered. Figure 1 also shows a slight\ndownward trend for incidents due to this subset of “detectable” causes. A downward trend is also shown if only\nsignificant incidents due to external or internal corrosion are counted.\nThe IM regulations required gas transmission operators to develop an IM program by December 17, 2004 and to\ncomplete baseline assessments of at least 50% of covered segment mileage by December 17, 2007. Comparing\nincident history for 2005-2007 vs. 2008-2010 shows a lower average yearly number of significant incidents for the\nlater period:\nTable 1: Incident History 2005-2010\nPeriod Yearly Average Number of\nSignificant Accidents - All\nCauses\nYearly Average Number of\nSignificant Accidents –\n“Detectable Causes”\nYearly Average Number of\nSignificant Accidents -\nCaused by Corrosion\n2005-2007 59 34 14\n2008-2010 52 27 8\nThe average number of incidents per year is 13% lower in the later period for all causes, 24% lower for incidents\nwith causes that may be detected by integrity assessments, and 72% lower for incidents caused by corrosion.\nAlthough much of the Integrity Management requirements address risks for all parts of a pipeline system, the IM\nrequirements for integrity assessment and repair primarily affect risks from line pipe and do not directly apply to\nother pipeline facilities such as compressor stations and regulator/metering stations4. If only line pipe incidents are\nincluded, and incident causes are limited to corrosion and other causes that could be detected by integrity\nassessments, then the incident trend over 2005-2010 is as follows:\nin annual reports have increased slightly, but the increase (around 1%) is not considered to have a significant effect\non the trends shown here.\nOnly onshore gas transmission pipelines are included in this analysis.\n4 Risks from these facilities are addressed by other IM requirements, such as requirements to implement other\npreventive and mitigative measures.\nPage 6 of 18 February 2011\n\n<<<PAGE 9>>>\n\nGas Transmission Integrity Management Progress Report\n35\nNumber of Significant Onshore Incidents\n30\n25\n20\n15\n10\n5\n0\n2005 2006 2007 2008 2009 2010\nLine Pipe Detectable Causes Linear (Line Pipe Detectable Causes)\nFigure 2: Significant Onshore Gas Transmission Pipeline Incidents - Line Pipe, \"Detectable\" Causes Only\nFor line pipe only, the number of significant incidents fluctuates over 2005-2009, with a flat to slightly increasing\ntrend.\nThe requirements of the integrity management regulations directly apply to pipeline segments identified by\noperators as high consequence areas (HCAs), which is a small portion (around 7% nationwide) of gas transmission\npipelines. Gas transmission incident reports have not identified which incidents occur in HCAs, but HCAs are\nprimarily located in the areas around pipelines with the highest population density and highest density of occupied\nbuildings.\nPage 7 of 18 February 2011\n\n<<<PAGE 10>>>\n\nGas Transmission Integrity Management Progress Report\n2. Accelerate and Improve Integrity Assessments\nThe IM rule requires that operators conduct baseline assessments on covered segments of their pipeline.\nAssessments can be performed using in-line inspection tools (aka “smart pigs”), hydrostatic pressure testing, and\ndirect assessment (for selected threats). Operators were provided more than seven years in which to complete all\nof their baseline assessments and then are required to periodically reassess their pipelines at a frequency not to\nexceed seven years. Gas transmission operators are required to complete the initial baseline assessments by\nDecember 17, 2012.\nAs part of each IM inspection prior to that deadline, PHMSA inspectors carefully reviewed the operator’s Baseline\nAssessment Plan and the progress toward meeting the compliance deadline. These inspections demonstrate that\noperators are on pace to complete their baseline assessments in advance of the deadline. Furthermore, each year\noperators provide PHMSA with a performance metrics that include information on their integrity assessments and\nrepairs, including mileage inspected and repairs performed. These annual reports, signed by the company’s senior\nexecutive, likewise showed operators are making adequate progress toward completing baseline assessments on\ntime.\nSome highlights from the performance metrics include:\n PHMSA regulates approximately 292,000 miles of gas transmission pipelines in the United States.\n The approximately 19,100 miles of gas transmission in covered segments, to which the IM rules apply,\nrepresents approximately 6.5% of the total gas transmission pipeline mileage in the U.S.\n From 2004-20095, approximately 140,000 miles of Gas Transmission pipelines2 have been inspected using\none or more of the assessment methods specified in the IM rules. These assessments were performed on\ncovered segments, as well as many other miles of pipelines. See Figure 3.\n Since the IM Program’s inception, there have been over 1,052 conditions repaired that required immediate\nattention, over 2,239 other conditions repaired on a scheduled basis.\n In 2007 alone, 258 conditions were repaired that were deemed by the rule to be serious enough to warrant\nimmediate attention in covered segments. In 2008, 146 immediate conditions were repaired and in 2009,\n124 immediate conditions were repaired.\n The number of these immediate conditions repaired has declined in 2008 and 2009, suggesting that the rule\nhas achieved one of its associated, primary benefits. That is, operators were required to identify their\nhighest risk segments and concentrate their initial assessments in the early program years on segments that\nwere likely to have more anomalies.\n5 2010 Annual Report submissions are not required until June 2011.\nPage 8 of 18 February 2011\n\n<<<PAGE 11>>>\n\nGas Transmission Integrity Management Progress Report\nFigure 3 – Miles of Gas Transmission Pipeline Inspected Under the IM Rule 2004-2009\n Also in 2009, approximately 251 other conditions were repaired or mitigated on a scheduled basis as\nrequired by the IM Rule. The total number of repairs in the “scheduled” category has not decreased as\nnoticeably. While the reasons for this continued rate of discovery are not entirely clear, continued operator\nvigilance in detecting mitigating, and ultimately preventing the anomalies remains a critical element of\nindustry IM implementation.\n In addition to repairs in segments that can potentially affect HCAs, PHMSA believes operators are addressing\na number of defects that are outside covered segments. However, operators are not required to report this\ndata, so the extent to which pipelines outside of covered segments are being repaired is not known.\nWhile the use of assessment tools is invaluable in identifying pipeline conditions that warrant repair, they are not\ntechnically capable of solely discovering all potential conditions that can lead to a loss of pipeline integrity.\nTherefore, it is important that all required elements of operator IM Programs – not just those portions specifically\nrelated to assessments – be fully developed and implemented to effectively manage pipeline integrity. The next\nsection addresses the broader development of operator IM Programs.\nPage 9 of 18 February 2011\n\n<<<PAGE 12>>>\n\nGas Transmission Integrity Management Progress Report\n3. Promote Rigorous Operator IM Programs\nThe IM rule identifies 16 program elements that must be part of an operator’s IM program. These required program\nelements are:\n Identifying high consequence areas (Covered Segment Identification)-includes identifying new HCAs\n Developing and implementing a Baseline Assessment Plan to conduct integrity assessments on these HCA\naffecting pipeline segments (Baseline Assessment Plan) - includes a process to minimize safety and\nenvironmental risk when performing assessments\n Identifying the threats to pipeline integrity for each covered segment\n Developing and implementing a Direct Assessment Plan (if applicable)\n Remediating potentially injurious pipeline anomalies identified through assessments (Remediation)\n Continually evaluate pipeline risks and conduct re-assessments of pipeline segments that could affect HCAs\non an on-going basis (Continual Assessment)\n Developing and implementing a Confirmatory Direct Assessment Plan (if applicable)\n Identifying and implementing additional preventive and mitigative measures to address the highest risks\nidentified through risk analysis (Preventive and Mitigative Measures)\n Measure IM Program performance and make improvements as necessary (Performance Evaluation)\n Recordkeeping\n Management of Change\n Quality Assurance\n Communications Plan\n Procedures to provide risk analysis or IMP to regulators\nPHMSA’s federal IM inspections are structured to examine both the development and implementation of each\nprogram element. A comprehensive set of inspection protocols is used by inspectors to assure operators comply\nwith the prescriptive requirements in the IM rule, and are developing IM programs consistent with the process-\nbased requirements in the rule. Figure 4 shows the number of issues identified during the 78 federal inspections\nconducted as of December 2010 for each of the program elements.\n450\n400\n350\n300\n250\n200\n150\n100\n50\n0\nFigure 4 - Number of Issues Identified per Completed Inspection for each Program Element\nPage 10 of 18 February 2011\n\n<<<PAGE 13>>>\n\nGas Transmission Integrity Management Progress Report\nOperators have generally identified their pipeline segments that can affect HCAs and have processes in place to\nidentify when conditions around the line change (e.g., a new housing development adjacent to the pipeline right-of-\nway). Operators are making acceptable progress toward completing their baseline assessments. Finally, operator\nrisk analysis methods are improving, though as noted later there is still work to do for these methods to be more\nuseful in supporting broader risk management decisions.\nTable 2 lists the most frequently identified problems from the first round of gas transmission IM inspections. Most\nof these concerns relate to integrating data and using risk analysis to improve the evaluation of integrity assessment\nresults; identifying and implementing additional preventive and mitigative measures; and determining the\nappropriate frequency and methods for re-assessment.\nIn addition to simply counting the issues observed during inspections, PHMSA has also established the relative risk\nor severity of each inspection issue. Figure 5 shows the relative risk of inspection findings for operators discovered\nin their first PHMSA inspection.\nArea Risk Ranking\nRound 1 Gas\nTransmission IMP Inspections\n2.50\n2.00\nRisk Ranking\n1.50\nMean\n1.00\nMedian\n0.50\n0.00\nFigure 5 – Severity of Inspection Findings by Program Element\nPage 11 of 18 February 2011\n\n<<<PAGE 14>>>\n\nGas Transmission Integrity Management Progress Report\nTable 2 - Most Frequently Observed Issues – 1st Round of Operator Gas IM Inspections\nNo. of\nIssues\nfound\n% of\ninspections\nthat noted\nthis issue\nIssue Category\n44 56% Interactive threats from different threat categories were not adequately evaluated\n32 41% A documented decision-making process to determine which measures should be implemented was not\nadequately developed and/or implemented\n28 35% Non-mandatory requirements from industry standards or other documents that are invoked by Subpart O were\nnot adequately addressed\n27 34% Procedures did not adequately describe the requirements to update the HCA analysis\n27 34% Procedures did not adequately document requirements to gather and/or integrate data.\n26 33% All of the threats required by the rule and standard for a prescriptive program were not adequately considered\nand/or evaluated\n25 32% An adequate process to decide if automatic shut-off valves or remote-control valves are an efficient means of\nadding protection was not developed and/or implemented\n25 32% When using outside resources to conduct processes that affect the quality of the integrity management process\nadequate quality was not ensured\n24 30% Procedures did not adequately describe how to identify HCAs using Method 1 and/or Method 2\n24 30% Specific threats for a particular pipeline segment were eliminated from consideration without adequate\njustification\n24 30% The plan for collecting, reviewing, and analyzing data was not adequate\n24 30% Process/procedures to identify and implement additional measures to prevent and mitigate a pipeline failure\nwere inadequate\n23 29% Procedures to determine identified sites were inadequate\n22 28% Procedures did not adequately document requirements for discovery, evaluation and/or remediation\nscheduling\n20 25% System maps or other suitable means of documenting the pipeline HCA segment locations were not\nappropriately utilized\n20 25% Procedures for conducting periodic evaluations were inadequate\n20 25% Changes to pipeline systems were not adequately considered in the integrity management program\n19 24% The decision-making process did not adequately consider both likelihood and consequences of pipeline failures\n19 24% Adequate reviews of the integrity management program were not required and/or adequately implemented\n18 23% The data sources specified in Table 2 of B31.8S were not adequately utilized during data gathering\n18 23% Individual data elements were not adequately brought together and analyzed (i.e., inadequate data integration)\n18 23% Procedures did not adequately document all requirements to develop, implement, document, and/or\ncontinually improve the risk assessment\n18 23% Adequate requirements were not specified to record and monitor anomalies that are classified as \"monitored\nconditions\"\n17 21% Data as specified in Table 1 of B31.8S was not adequately gathered and/or evaluated\n17 21% The criteria for discovery were not adequately documented\n16 20% The method or combination of methods used to identify HCAs was not adequately documented for each\ncovered segment\n16 20% Enhancement to the Damage Prevention Program to require the collection in a central database location-\nspecific information on excavation damage that occurs in covered and non-covered segments and the root\ncause analysis were\n15 19% New information was not adequately incorporated in a timely and/or effective manner\nPage 12 of 18 February 2011\n\n<<<PAGE 15>>>\n\nGas Transmission Integrity Management Progress Report\nThe preceding charts suggest that industry is not meeting PHMSA expectations to identify threats and analyze risks\nto its pipelines. Addressing the broad set of threats requires that operators develop the processes and tools to\nidentify and analyze the risks unique to each pipeline. These risks are dependent on the pipeline location, operating\nenvironment, commodity transported, and many other factors. The IM rule also requires operators to have\nsystematic approaches to use this risk information to identify and implement additional preventive and mitigative\nmeasures. If operators are to successfully and significantly reduce their operational risk, it is critical that the\nmeasures taken are based on a sound understanding of what is actually driving that risk and how those drivers can\npractically be impacted. As a specific example of the difference between a mature IM Program and one in the early\nstages of development, the risk analysis approach to support evaluation of potential preventive and mitigative\nmeasures needs to be more detailed than a simple approach used to prioritize pipeline segments for the baseline\nassessments.\nThe preceding charts also indicate the continued need for PHMSA vigilance with respect to industry remediation of\nanomalies identified during assessments (e.g., completing repairs within required timeframes, implementation of\nrequired pressure reductions), quality assurance, direct assessment, and identification of HCA segments (covered\nsegments).\nWhile operators understandably devoted significant resources to completing their baseline assessments to meet the\ndeadlines in the regulations, they now need to devote more effort and resources to those elements considered to\nbe representative of a mature IM program, such as threat identification and risk analysis (including data integration),\npreventive and mitigative measures, continual evaluation and assessment, and their own internal program\nevaluation process.\nPage 13 of 18 February 2011\n\n<<<PAGE 16>>>\n\nGas Transmission Integrity Management Progress Report\n4. Strengthen Government Oversight\nIn 2005, PHMSA launched a new inspection program to assure compliance with the new IM requirements and\npromote improved operator IM Programs. A comprehensive set of inspection protocols were developed that not\nonly checked for compliance with the rule’s prescriptive requirements, but also supported a detailed audit of an\noperator’s management and analytical systems, processes, and practices to manage pipeline integrity. PHMSA\ninspects the IM Programs of interstate gas transmission operators that PHMSA’s regulates as well as some intrastate\npipeline operators.\nWhen operators fall short of meeting the rule’s requirements for IM program development, PHMSA takes\nenforcement action to address program deficiencies as well as to accelerate program development. PHMSA issues\ncivil penalties as well as compliance directives which dictate the corrective actions which operators must take to\naddress program deficiencies. PHMSA has issued enforcement letters for most of its IM inspections. When\nviolations of the rule’s prescriptive requirements occur, PHMSA has not hesitated to exercise its civil penalty\nauthority. For PHMSA’s first round of operator IM inspections, the average civil penalty was approximately\n$125,000. Further, when program deficiencies are identified, PHMSA likewise has not hesitated to exercise its\ndirective authorities either. Approximately 28% of PHMSA’s enforcement actions are in the form of a compliance\ndirective known as a Proposed Compliance Order, which along with Notices of Amendment, are used to achieve\nneeded programmatic improvements.\nTable 3 – Integrity Management Enforcement Results\n% of Inspections\nResulting in\nEnforcement\nAction\n% of Inspections\nResulting in\nProposed\nCompliance Order\n% of Inspections\nResulting in\nProposed Civil\nPenalty\nAverage\nProposed Civil\nPenalty6\n76% 28% 16% $125,183\nFigure 6 shows how frequently each type of enforcement action has been applied.\n7 As can be seen, the Notice of\nAmendment (NOA) action is the most frequently used compliance tool following IM inspections. NOAs are used to\ncommunicate needed program and process improvements to operators. Because the development and maturation\nof an IM Program takes significant operator time and resources, the NOA has been used frequently in the early\nstages of the IM oversight program to communicate PHMSA expectations for process-based requirements in the rule\nand facilitate the timely development of operator programs in the desired direction.\n70%\n60%\n50%\n40%\n30%\n20%\n10%\n0%\nFigure 6 – Percentage of Inspections which Resulted in Each Type of Enforcement Action\n6 Average does not include cases with no civil penalty proposed.\n7 Some inspections result in more than one type of enforcement action\nPage 14 of 18 February 2011\n\n<<<PAGE 17>>>\n\nGas Transmission Integrity Management Progress Report\n5. Increase Public Assurance in Pipeline Safety\nThe extensive performance and process-based requirements in the IM rule represent a significant departure from\nPHMSA’s prior practice of issuing largely prescriptive regulations. PHMSA leadership recognized that a major\noutreach effort was required to both communicate to operators what was expected, and to foster the public’s\nunderstanding of the rule and its safety improvement objectives.\nSince the initial publication of the IM rules, PHMSA has taken unprecedented steps to inform\nand involve the public and its regulated community. PHMSA conducted three public\nmeetings since the rules were published to explain the rule and communicate PHMSA’s\nexpectations for compliance. The last of these workshops described some of the lessons\nlearned from the early inspections providing the public with an opportunity to understand\nhow the new rules were being enforced. The workshops also provided an opportunity for\noperators to share noteworthy integrity management practices and better understand\nPHMSA’s oversight approach for this performance-based rule.\nPHMSA has also held several workshops focused on a specific subjects and challenges\noperators face in managing safety and integrity. In particular, workshops on the Use of In-\nLine Inspection Devices and Anomaly Assessment and Repair were held in 2005 and 2008,\nrespectively. The presentation material from these workshops was made available to a\nbroader audience through PHMSA’s web site.\nShortly after the rule was published, PHMSA launched the “Integrity Management” web site\n– a comprehensive resource of information related to the new IM rule .\nThe IIM web site provides copies of the rule language, a flow chart illustrating the IM process,\na glossary of terms and other basic reference material related to IM (see menu from the web\nsite to the right). The web site includes more than 200 Frequently Asked Questions (FAQs) to\nexplain the rule provisions, PHMSA’s compliance expectations, and PHMSA’s oversight\nprogram. In the early development of the FAQs, the questions were collected through the\npreviously mentioned public meetings, individual public and operator inquiries, and\nsubmissions from industry trade groups. The web site itself has a feature where users can\nsend questions to PHMSA.\nThe IIM site is heavily interlinked. For example, clauses in the IM rule are linked to related\ninspection protocols so users can readily access additional information about PHMSA\nexpectation for key rule requirements.\nPage 15 of 18 February 2011\n\n<<<PAGE 18>>>\n\nGas Transmission Integrity Management Progress Report\nSince 2004, Gas Transmission operators have been required to file performance metrics that contain integrity\nmanagement ","truncated":true,"body_characters":45477}